Good day, and welcome to the Magnolia Oil & Gas first quarter 2022 earnings release and conference call. All participants will be in a listen-only mode. Should you need assistance, please signal a conference specialist by pressing star then zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on a touch-tone phone. To withdraw your question, please press star then two. Please note this event is being recorded. I would now like to turn the conference over to Brian Corales. Please go ahead.
Thank you, Matt, and good morning, everyone. Welcome to Magnolia Oil & Gas' first quarter earnings conference call. Participating in the call today are Stephen Chazen, Magnolia's Chairman, President, and Chief Executive Officer, and Chris Stavros, Executive Vice President and Chief Financial Officer. As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. Additional information on risk factors that could cause results to differ is available in the company's annual report on Form 10-K filed with the SEC. A full safe harbor can be found on slide two of the conference call slide presentation with the supplemental data on our website.
You can download Magnolia's first quarter 2022 earnings press release, as well as the conference call slides from the investor section of the company's website at www.magnoliaoilgas.com. I will now turn the call over to Mr. Steve Chazen.
Thank you, Brian. Good morning, and thank you for joining us today. We continue to execute on our strategy and business model, which limits our spending to 55% of our EBITDAX on drilling and completing wells. This is expected to deliver mid-single digit annual production growth along with high full cycle operating margins. The remaining 45% will be allocated towards a mix of accretive bolt-on acquisitions, dividends, and share repurchases. During the first quarter of 2022, we grew our total production 15% year-over-year and 3.5% sequentially, while spending just 28% of our EBITDAX drilling and completing wells and generating operating income margins or EBIT of 62%. Quarterly production was at the high end of our guidance, mainly due to better performance at our Giddings assets.
Total production at Giddings grew 24%, and oil production grew 31% compared to the same period last year. Our free cash flow in the first quarter was approximately $200 million, and we distributed nearly all of it to our investors through share repurchases and dividends. We repurchased a total of 6 million shares during the first quarter, reducing our total diluted share outstanding by 9% compared to last year's first quarter. We also paid the second installment of our semi-annual dividend of $0.20 a share, which is based on our full year 2021 results recast at $55 oil, bringing the total dividend associated with 2021 results to $0.28 per share.
Despite the significant return of cash to our shareholders, we ended the quarter with $346 million of cash on our balance sheet, roughly unchanged during the quarter. Together with our 15% production growth and 9% decrease in our total diluted share count, our year-over-year production per share growth was 27%. The combination of continued moderate growth and share reduction provides greater capacity for dividend growth over time. We continue to operate two drilling rigs and expect to maintain this level of activity for the balance of the year. Efficiencies such as faster drill times, longer laterals, and more wells per pad are expected to lead to more net wells during the year, leading to approximately $25 million of additional capital. We expect to see another $25 million of spending resulting from increased oil service cost inflation for both material and labor.
The longer laterals and shorter cycle times are expected to benefit our production volumes during the remainder of 2022 and into early next year. As a result, we now expect our full year 2022 production growth to exceed 10% compared to our previous forecast of high single digit growth. Our operating team continues to make strong progress, steadily advancing the development of our Giddings asset, and we've been successful in offsetting some of the oil field cost inflation through ongoing efficiency gains. We have improved our drilling feet per day by about 20% compared to a year ago and increased the lateral length of the average Giddings well by about 15% to 8,000 feet, with some wells expected to surpass 10,000 feet.
With Giddings still in relatively early stages of development, our operating team's improved understanding and growing experience will allow us to increase the oil and gas recoverability from the asset through the application of modern completion techniques and further full field efficiencies. Giddings now makes up 80%—nearly 60% of our total company production compared to 1/3 of our volumes in 2019. Magnolia remains very well positioned in the current environment. We believe that reinvesting in our business to achieve moderate, predictable annual volume growth is important for a company of our size while balancing this with meaningful amount of cash returned to our shareholders.
Our gradual and measured approach toward both the appraisal and development of Giddings Field has created operating efficiencies, leading to some additional net wells and higher growth this year. At current product prices, we expect our capital for drilling and completing wells to be less than a third of our cash flow, well below our 55% spending cap, and resulting in significant free cash flow. The absence of hedges on our production allows for strong product price realizations. Most of the free cash flow is expected to be allocated towards improving the per share value of the company, including our plan to repurchase at least 1% of our outstanding shares each quarter. We also expect our dividend to grow at least 10% annually as a result of production growth, combined with a steady reduction of our share count. I will now turn the call over to Chris.
Thanks, Steve, and good morning, everyone. I plan to review some items from our first quarter and referring to the presentation slides found on our website. I'll also provide some additional guidance for the second quarter and the remainder of the year before turning it over for questions. Beginning with slide four, which shows a summary of our first quarter, Magnolia continued to execute on our business model, building on last year's accomplishments, and as demonstrated by our very strong first quarter 2022 financial and operating results. We established corporate records for many of our key financial metrics during the first quarter, including net income, diluted earnings per share, free cash flow, and most notably, operating income margins or EBIT of 62%.
These results were supported by the absence of hedges on our production, providing strong product price realizations, our efforts around cost containment, and continued moderate production growth. We generated total net income for the quarter of $209 million, including an effective tax rate of 8%, which was at the high end of our guidance and due to stronger product prices. Using our total diluted shares outstanding including both Class A and Class B common stock, this calculates to $0.92 per diluted share for the first quarter. Our adjusted EBITDAX was $298 million in the first quarter. Total D&C capital of $83 million was lower than our earlier guidance, representing just 28% of our EBITDAX.
Overall, company production volumes grew 3.5% sequentially and 15% year-over-year to 71.8 thousand barrels of oil equivalent per day in the first quarter. Looking at the quarterly cash flow waterfall chart on slide 5, we started the year with $367 million of cash. Cash flow from operations before changes in working capital was $268 million during the period, with working capital changes and other small items impacting cash by $28 million. Our D&C capital spending, including land acquisitions, was $84 million. As Steve mentioned, we returned the majority of our free cash flow to our shareholders during the first quarter. Most of this cash return was in the form of share repurchases, where we spent $130 million buying in 6 million shares.
Cash allocated to repurchasing our shares during the first quarter was more than 50% greater than our capital outlays for drilling and completing wells. Looking at slide 6, this illustrates the progress of our share reduction since we began repurchasing shares in late 2019. Since that time, we have reduced our total diluted share count by nearly 43 million shares, or approximately 17%. Magnolia's weighted average fully diluted share count declined by 3.6 million shares sequentially, averaging 227.4 million shares during the quarter. We currently have 14.3 million shares remaining under our current repurchase authorization, which is specifically directed towards repurchasing shares in the open market.
As shown on slide seven, we also used $49 million of cash or $0.20 a share to pay our final semi-annual dividend associated with our full year 2021 results, recast using oil prices of $55. Inclusive of the interim dividend paid in the third quarter of last year, the total dividend associated with our 2021 results was $0.28 per share. We expect our dividend to grow at least 10% annually based on the continued successful execution of our strategy. Our philosophy is to continue to maintain low leverage and a strong balance sheet. We have approximately 0 net debt and expect to generate a significant amount of free cash flow through the year.
Our $400 million of gross debt is reflected in our senior notes, which are callable later this year and do not mature until 2026. Including our first quarter ending cash balance of $346 million and our undrawn $450 million revolving credit facility, our total liquidity is approximately $800 million. Our condensed balance sheet and liquidity as of March 31 can be found on slides eight and nine, Turning to slide ten and looking at our per unit cash costs and operating income margins. Despite the substantial increase in product prices over the past year, we've seen only a small increase in our total costs.
Our total adjusted cash operating costs including G&A, were $13.18 per BOE in the first quarter of 2022, an increase of $2.45 per BOE compared to year-ago levels. Yet our revenue per BOE rose by more than $21 per barrel over the same period. Including our DD&A rate of $8.21 per BOE, which is generally in line with our F&D costs, our operating income margin for the first quarter was $36.48 per BOE or 62% of our total revenue. Simply put, we captured 88% of the revenue increase in our operating income margin on a year-over-year basis. Looking at a few specific cost items, our overall lease operating expenses increased compared to the prior year, mainly due to higher workover-related activity and some general labor and materials inflation.
The workover activity, which can vary from period to period, has already started to have a positive influence on our production. The increase in GP&T expense is largely a result of much higher natural gas and NGL prices. As prices move higher, the GP&T expense would also move higher and vice versa. Finally, G&A expenses declined on a year-over-year basis as a result of savings realized from last year's termination of the EnerVest operating services agreement, and partly offset by some additional personnel costs associated with our growth. Looking at our total cost structure, we would expect the remainder of the year to be similar to first quarter levels on a per BOE basis.
Turning to some guidance for the second quarter and our view for the remainder of 2022, we are currently operating two drilling rigs and plan to continue at this level of activity through the end of the year. One rig will continue to drill multi-well development pads in our Giddings asset. The second rig will drill a mix of wells in both the Karnes and Giddings areas, including some appraisal wells in Giddings. We continue to improve our efficiencies in the Giddings field, which should help to offset some of the oil field cost inflation and will also lead to some additional net wells this year. Our total capital is now estimated to be approximately $400 million for this year, which represents an increase of $50 million from our earlier expectations.
As Steve discussed, about half of this increase is a direct result of drilling faster and drilling longer laterals, leading to more net wells for the year. The other portion of the increase is due to oil field service cost inflation for both materials and labor. Despite the modest increase in capital for this year, we still expect our spending to be less than it was during 2019. This was during a period when we were also operating 2 rigs, when our production was more than 10% lower than current levels and when oil prices were around $60 and natural gas was under $3. Our cost per lateral foot for drilling and completing wells this year is expected to be about half the level when compared to 2019.
As a result of the additional efficiency-driven net wells, we now expect our full year 2022 production growth to exceed 10% compared with our earlier guidance of high single-digit growth. Production growth at Giddings this year should be around 25%. Looking at the second quarter of 2022, we expect total production to be between 72,000 and 74,000 BOE per day. Most of the wells are scheduled to be turned on, turned in line in the latter part of the second quarter, which is expected to benefit production growth during the back half of the year. Our D&C capital is estimated to be between $100 million and $110 million for the second quarter, and is expected to be in this range for the remainder of the year, consistent with the $50 million increase I described earlier.
Should product prices remain at their current elevated levels, we would expect our second quarter effective tax rate to be between 8% and 10%. As I mentioned earlier, we remain completely unhedged for both our oil and gas production, allowing us to fully capture higher product prices. Oil price differentials are anticipated to be approximately a $3 per barrel discount to MEH and in line with recent quarters. Our fully diluted share count for the second quarter is estimated to be approximately 223 million shares, which is 8% below year-ago levels. We're now ready to take your questions.
We will now begin the question and answer session. To ask a question, you may press star then one on your touch tone phone. If you're using a speaker phone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star then two. In the interest of time, we ask participants to please limit yourselves to one question and one follow-up. At this time, we will pause momentarily to assemble our roster. Our first question will come from Neal Dingmann with Truist. Please go ahead.
Morning, all. Thanks for the time. My first question guys is on capital allocation specifically. Pretty amazingly, y'all were able to continue to spend, you know, about 50% more on shareholder returns than into the drill bit. I'm just wondering two things here. One, is this largely due to the strong well results you continue to see at Giddings? Do you anticipate this proportion of spending on the foreseeable future?
The Giddings wells are doing very well. The Giddings program is doing very well. I think that you have to attribute the good, the ability to spend less and produce more, basically is Giddings, although Karnes has done well also. I mean, basically, you know, there's only a few items you can spend the excess on. You can spend it on dividends, you can spend it on share reduction, or you can spend it on acquisitions. You know, we spent essentially all of it on dividends and share reduction in the second quarter. You know, it's probably gonna be similar.
You know, we'll probably spend the bulk of it on a share reduction, you know, as long as the share price stays reasonable. We're only trading at, you know, a very low multiple of earnings or cash flow. So long as you have this money, you know, we'll put it in the share reduction because, you know, we believe, maybe rightly or wrongly, that as we reduce the shares, it basically allows for larger and larger dividend increases. Because the way we manage the dividend size is we recast the current year in the $55 oil environment.
Figure out how much we can afford to spend on dividends out of that. As we reduce the share count and as production goes up, the percentage of the growth of the dividend will follow that. If we bought in 4% of the shares and grew the production 6% in the current year, then, you know, dividend would go up 10% roughly. Obviously, if we're doing better than that, more share reduction and more buy and growth, the dividend will be high growth will be higher than 10%.
Giddings, if you could speak maybe broadly as to what the, you know, I don't know what terms you can kind of color you can give on this, but what the areal extent of your current delineation program, and then how concentrated is the current development side of that program with those two rigs?
The development program is fairly concentrated in a couple of areas, maybe totaling you know, less than 100,000 gross acres. However, our understanding of the reservoir has grown a lot over the last year. We spent a lot of effort trying to understand the reservoir better. Without being too explicit, the areal extent is growing geometrically because we find that areas that we thought wouldn't work, we found ways to make it work by you know, better drilling techniques or avoiding depleted reservoirs in the path. The chalk is quite thick here, and there are areas that were depleted by the earlier wells. If we can avoid those depleted areas, we'll find large scale pockets of oil.
We think that's working pretty well at this point. It sort of opens the size of the area, areal extent quite a bit. We can't really say how much just 'cause we don't know exactly, but it does open the areal extent quite a bit. Our inventory, you know, we try to keep a five-year drilling program set so we always have five years, so we know what we can do. We could be much longer than that with two rigs. You know, it actually, you know, it's a gift that keeps giving. The better we understand, the more we can, the more growth there'll be over time.
We would view the 6%, you know, mid-single digit growth, but that includes some decline in Karnes probably, you know, as a conservative number.
Very good. Thanks for the details, Steve.
Thanks.
Our next question will come from Leo Mariani with KeyBanc. Please go ahead.
Hey, guys. Just wanted to follow up a little bit at Giddings here. You obviously have talked about, you know, better well performance there. Would there be any way to, like, give us a, you know, kind of a round number quantification like, hey, these wells are 20% better than they were last year on productivity? Anything you could share on that would be helpful.
Well, it's you know something like 20%. You know, we don't know exactly 'cause you know it varies. You don't drill exactly the same well every you know from year to year. You know, we're drilling longer laterals. We were you know 4,000 feet you know a couple years ago, and we're now drilling 8,000-10,000-foot well. Our productivity is soaring. We're drilling the wells a lot faster, and the less time you spend in the hole, the better off you are. You know, it's significantly better. Of course, you know, $100 oil, everything you know it always looks smart.
Yep. Okay. Makes sense. Then I guess just based on the answer to kind of your previous question, I know the plan was to drill some step out appraisal wells here in 2022. Should I take it that you had some incremental success with that here this year as you kind of talked about some of the areas that maybe you didn't think would work? Just wanna make sure I've understood that.
Yeah, that's right. We're gonna drill some more. We're trying to fix this, figure out what the right spacing is, part of this program to try to, you know, optimize each well. We've spent some time with that also to try to figure out what the correct spacing is. We're closing in on that to some extent. The answer to your question is that the appraisal program is going well.
Okay, very helpful. I wanted just to see if you could maybe, you know, quantify a little bit, what the kinda rough increase was here in 2022, and the number of sort of lateral feet drilled kinda versus the earlier budget. You obviously had referenced, you know, clearly being able to go faster on these wells. You know, is it like a 10% increase in lateral feet or something versus that earlier budget? Just trying to get a ballpark on what that might be.
I don't know what we put.
Yeah.
In the earlier budget. Chris?
Yeah, no, I think what we said was we're drilling wells on average that are exceeding 8,000 feet, you know, maybe a little higher than that. You know, we continue to sort of push more to the extent that it makes sense. I mean, as Steve said in his remarks, I mean, some of the wells that we're drilling will exceed and surpass 10,000 feet. Last year, it was sort of running 7-ish.
You know, the simple way to look at it is that virtually every month we drill. That's, take the drill part of it. We drill a well at a record short period of time. What's happened is we're gonna drill more wells with two rigs than we thought we were gonna drill, even with the longer laterals and all of those stuff. What that does is create more completion costs. What you're looking at with the $50 million is actually the completion cost of the extra wells that are caused by the quicker drilling time. I think if you want to think of it, that's an easy way to come up. We wind up drilling and completing more net wells than we thought.
You know, we continue to set records virtually every month for how fast we're drilling the well. It's a consequence of a better understanding of the reservoir so that you can skip over some of the problems that might be in the wellbore.
Okay. Great update. Sounds like things are going well. Thanks, guys.
Our next question will come from Zach Parham with J.P. Morgan. Please go ahead.
Thanks, guys. I guess first one just on cost inflation. Can you talk a little bit about the drivers of the CapEx increase, particularly the portion driven by inflation? Maybe just give us some color on how contracted you are on some of your key service lines for the rest of the year.
Yeah. Chris, why don't you answer that for him?
I mean, first off, we've got everything, all the materials and necessary items to complete our, you know, our scheduled plan for this year. You know, really sort of the point is what's not up. I mean, sort of everything has moved higher, whether it's. It's mostly focused on your completions, and some labor, too. You know, it's not so much the sand necessarily, but it's hauling it. You know, you try to look at some specific things that you can do, make some arrangements or tricks on moving sand. But look, every item is up. What we baked into, you know, the updated numbers is pretty much accommodating for most, if not all of it, for this year.
We also continue to contract ahead. We, you know, we're not stopping at the end of the year. As we, you know, as the year progresses, we continue to add to the tail. We always have a significant amount of, you know, contracted running room ahead.
Got it. Maybe just to follow up on cash return. You know, you've talked about basing the dividend on the $55 and $2.75 price environment. Given that the strip has traded well below that level.
We'll probably price it to do it this time.
Got it.
Go ahead.
You'll consider taking that price up when you lay out the dividend.
Yeah. We can clearly take the gas price up. We base it on that so that we can always pay it. You know, a true dividend investor, I don't mean somebody who just wants to participate in oil price. A true dividend investor wants this certainty of getting it, which is caused by your balance sheet and how much you pay out of your earnings and a growth rate that they can count on. That's what this base dividend is intended to cover. You know, it'll grow, you know, at least 10% a year, maybe more earlier. You know, who knows what later, but. It's intended to appeal to the person who wants the sure dividend.
You know, beyond that, right now, the sensible strategy is to repurchase the shares. I think a significant disconnect between prospects for our industry and the stock price is an opportunity, you know, to buy your shares, which really shouldn't be missed. You know, I think that's the, you know, for certainly this year, that's really the plan. You know, once we get beyond that and it becomes more difficult to buy the shares or, you know, if the stock gods are kind, the stocks start to reflect some kind of reasonable terminal value for the industry. Right now, they think that the whole industry is gonna go out of business in five years.
I think that once we get beyond that, the stocks start to reflect a more reasonable valuation, then we'll look at, you know, other ways to return money through dividends. Right now, the focus is on buying as many shares, which I think are mispriced over time. I have more confidence in the product price than I probably ever had in my life, at least for the next few years. I think that a reevaluation of the industry from 4% of the S&P to maybe 10% is probably in order over time.
You know, the focus for now will be on the growing the base dividend as we promised and buying in the shares while they remain, you know, reasonably priced. Got it. Thanks for that color.
Our next question will come from Umang Choudhary with Goldman Sachs. Please go ahead.
Hi, good morning, and thank you for taking my questions. Early in the year, you had indicated strong macro environment in first half, and then you were concerned about slowdown in second half. Would love your updated thoughts on the macro here.
I don't know, you know. Predictions are always hard, especially about the future. You know, I don't know anybody who's got a particularly good record. For the industry, I don't see much risk during this year. Maybe there'll be some modest decline in oil price, but not much, because it's so tight. You know, the oil and gas gods up in the sky or wherever they're located have looked down on us, and they look at each other and look at the industry over time, the oil and gas gods say, "You know, I've given these guys lots of opportunity, and they continue to extract defeat from the jaws of victory. They continue, you know, to overproduce.
This time we're gonna make it so they can't. We're gonna tighten the labor markets, and we're gonna tighten the supply chain, and so we keep these. The oil and gas gods say, "This time we're gonna fix it so they can't overproduce and destroy the good thing." Not that they wouldn't if they couldn't, could. That's what's going on now. We have this environment where even if you wanted to grow a lot, you couldn't, because you can't get the supplies, you can't get the labor, you can't drill the wells. As long as that goes on, I think the product prices will be relatively strong. You know, a serious recession would hurt oil and gas, like, just like it hurts almost everything else.
You know, one instance, you know, when you raise interest rate, what are you doing? Well, you're punishing autos and the stock market. I don't know if that brings inflation down or not, but you know, they seem to think it will. As long as demand stays pretty good, you know, I don't see a bunch of supplies coming on. I don't. Not worried about Russia. I'm sure Russia is selling a fair amount of oil away from the general markets at discounted prices. I'm sure the Iranians are too. Even if this whole thing ended, there wouldn't be that much additional oil to come on the market. The demand is very good.
The Saudis don't, I don't think, plan on flooding the market with oil. You know, we're looking at pretty good product prices for the next couple of years, I think. Natural gas, you know, surprisingly strong, you know, basically competing as coal. I really think that, you know, we're in a pretty good place. Could there be a recession? Sure. Most recessions are caused by incompetence at the Fed. You know, I doubt if this next one will be a change of that policy or outcome. That's my view for what-
Yeah. Appreciate the color. That's really helpful. I guess on your point about higher natural gas prices, I was wondering, I mean, you do have a lot of acreage, which are gassier in your Giddings asset. Any thoughts around, you know, pulling that forward from a development cadence perspective? How does that tie into your thoughts between relative economics between oil drilling in Giddings and gas drilling in Giddings?
You know, oil I don't think is at a low price. You know, I don't want $7 gas or $100 oil, you know. How about some of each? It means we used to avoid the gassier areas and just drill oilier areas. Now, you know, it gives us more flexibility to drill around. You know, I can't really add a rig, as a practical matter. There's no rig to add at a reasonable price and with a good crew. I need a good crew usually to make it work. You know, if you wanted to add a rig, you wouldn't get a good crew right now. You know, I don't want bad crews. The bad crews make for bad problems.
I, you know, think we'll go along. We're not really differentiating between oil and gas anymore because the gas stuff works pretty good, especially in the NGL pricing.
No, that makes sense. Thank you.
Thanks.
Again, if you have a question, please press star then one. Our next question will come from Charles Meade with Johnson Rice. Please go ahead.
Morning, Steve, and Chris and Brian. I just wanna say I enjoy when your color, Steve, comes in the form of unfiltered opinions. I don't think you're looking for a role as a commentator on CNBC, but they could really use you.
Yeah. I was thinking of becoming a security analyst, but the pay isn't very good, so.
No, no, it sure hasn't been, especially in this wonderful sector. Actually I actually do have some serious questions about your assets here. First point, on your longer laterals. It's great that you're extending them from 7,000-8,000 feet on average. I'm curious though, this is for a long time been one of the best ways to increase your capital efficiency. I'm wondering, what's changed that you're doing this now? Are you going to a new area with just bigger leases and more lateral available to you with that work?
Is this instead perhaps something like you're doing more land work ahead of your rigs to put the longer laterals together? What are the drivers there?
You know, we don't have the same issues with land that we have, say, in Karnes or people have in the Permian. You don't have these land issues because, you know, we own so much of this. What you have is you drill through the rock. You have zones that are depleted from earlier wells. The question is how to sort of drill around them or keep yourself from losing circulation as you pass through them. We've learned how to do that, and therefore we can. It becomes less an issue of the loss of circulation as you pass through it, because we know how to deal with that or how to plan for it.
Got it. It's not a land limitation. It's a drilling engineering.
Yeah, exactly.
Got it.
It's within our control, not within the control of some guy who has a ranchette and lives in River Oaks.
Okay. Then second question, Steve, and I'd like to try to get you to opine a little bit more with the benefit of all your experience. You mentioned that you can't pick up another rig now because you'd be picking up a rig at a high rate, and it would have probably it'd have a green crew. As you play the movie forward in your head for Magnolia and the industry into 2023, are you concerned that just to pick up on that one issue of crews, that you might still have your two rigs, but that your crew is gonna get poached, you know, to start up a new crew somewhere, and you're gonna wind up with a 50% green crew?
Is that going to happen kind of across the industry and lead to more inflation in 2023?
I don't know about the inflation. Certainly they got to do something. You know, with only two rigs, the crew, you know, controlling the crew is easier, frankly, than somebody who has running 20 rigs or 25 rigs. You know, two, you know, we can make a deal with the contractor on the crew. You know, somebody who runs a lot of them, it's really hard to make that kind of decision. So the contractor will use those some people to train new ones. I don't know about inflation. You know, it certainly, you know, it might make it may make it less efficient.
Right.
You know, it's not inflation in the normal sense of the word, but instead of taking 20 days to drill a well, it takes 22.
Right. Not so much inflation, but efficiency could be on the,
Yes. You do have to, you know, we had this big downturn. A lot of people lost jobs, and to reattract them to the industry, you're gonna have to pay to do that. You know, maybe some layoffs at Amazon would help. Maybe get some of their truck drivers. You know, that's really. You know, you're gonna have to recruit them from somewhere to do this. Now, you can get them out of the community colleges and that sort of thing to start training them on your crews. It takes time, but you can actually do that if you work at it. We don't really have any turnover in our own people, in our field hands and stuff.
You know, the industry pays well and gives good benefits. I mean, it's not a bad industry to work, but we did have this downturn, and a lot of people went off to do other things. It turns out that some, maybe some of those other things were, you know, temporary.
Right. Thank you for sharing your insights, Steve.
Thank you.
This concludes our question and answer session, which also concludes our conference for today. Thank you for attending today's presentation. You may now disconnect.